First Downhole Application of Distributed Acoustic Sensing (DAS) for Hydraulic Fracturing Monitoring and Diagnostics

Molenaar, Mathieu M.; Hill, David J. T.; Webster, Paul; Fidan, Erkan; Birch, Bill

doi:10.2118/140561-ms

Cited by 56 publications

(17 citation statements)

References 4 publications

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“…The first mature distributed technology used for real-time injection profiling was DTS (Huckabee 2009) with DAS (Molenaar et al 2011); both currently take center stage in the industry as the next evolution in optical distributed measurements for downhole use. While DAS was acquired and processed on this project, this paper focuses on DTS results.…”

Section: Dts Analysismentioning

confidence: 99%

Using Distributed Optical Sensing to Constrain Fracture Models and Confirm Reservoir Coverage in the Permian Basin

et al. 2014

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Low-permeability basins present a tremendous challenge to effective completion and reservoir drainage, especially in known heterogeneous environments that present additional complexity. Several robust diagnostic techniques exist in the market currently that are identified as guides to improve completion and stimulation efficiency in basins that require hydraulic fracturing to make low-permeability environments viable. Some of these techniques include fracture modeling, microseismic mapping, diagnostic fracture injection test (DFIT) analysis, radioactive and chemical tracers, and pressure matching. During the past decade, fiber-optic sensing has been identified as an additional tool that can provide significant benefit to complement the more traditional approaches listed previously. In current commercial applications, this includes distributed temperature sensing (DTS), distributed acoustic sensing (DAS), distributed strain sensing (DSS), and optical point pressure and temperature solutions that can define wellbore characteristics through the entire well life cycle.This case study focuses on optical data acquired from a vertical well drilled in Ector County, Texas in the Permian Basin. The well was stimulated using a limited entry approach as a cased and cemented completion. The project attempted to resolve questions pertaining to the distribution of stimulation fluid to each interval, total hydraulic height growth association to each stimulation treatment, and total production contribution from each interval. This paper focuses on using the fiber-optic results in conjunction with other tools to define the stimulation treatment and completion effectiveness.A fiber-optic cable was deployed permanently behind the casing to acquire both DTS and DAS data during stimulation treatment, flowback, and production to review the entire well life cycle. Complementing the distributed optical measurements, fracture modeling was performed using data acquired by fiber optics to constrain the model, as well as openhole logging results to compare to the distributed optical results. A review of the post-job fracture model was compared to the DTS fracture height estimates. If a large discrepancy was observed between these two values, the post-fracture model was revisited to assess if other interpretations of the fracture model were reasonable. Distribution of fluid along the near wellbore was also assessed using DTS results to define hydraulic fracture height growth.

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Section: Dts Analysismentioning

confidence: 99%

Using Distributed Optical Sensing to Constrain Fracture Models and Confirm Reservoir Coverage in the Permian Basin

et al. 2014

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“…DAS allows a wide variety of applications ranging from real-time hydraulic fracture optimization (Molenaar et al 2011) to geophysical monitoring (Mestayer et al 2011 cost on-demand geophysical monitoring. Once the system is installed, no further well interventions are required, and repeat surveys offer the prospect of improved repeatability and increased time lapse sensitivity, while operational efforts are limited to seismic source requirements.…”

Section: Distributed Sensing-a Growing Toolbox Of Fiber-optic Techniquesmentioning

confidence: 99%

Fiber-Optic Sensing Technology Providing Well, Reservoir Information - Anyplace, Anytime

Koelman

2011

Journal of Petroleum Technology

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Technology Update Fiber-optic sensing is known in the oil and gas industry as a technology that allows continuous temperature profiling along entire well paths. However, surveillance applications focusing solely on temperature measurements are limited to recovery processes with a clear, unambiguous thermal signature. This has prevented fiber-optic sensing from becoming a widely deployed technology in oil and gas production. However, we are now witnessing a confluence of novel fiber-optic technologies that promise a much wider range of subsurface measurements. This opens new avenues in well and reservoir management and highlights the opportunity for fiber optics to become a pervasive oilfield technology. For this to achieve reality, the multiple sensing technologies being introduced by various providers need to be combined and deployment costs contained. The key enabler to achieving these goals is to bundle a selection of fibers into a single cable suitable for downhole deployment and optimized for monitoring a variety of in-situ data. Distributed Sensing—A Growing Toolbox of Fiber-Optic Techniques The individual sensing technologies are at various stages of development and derisking. Distributed temperature sensing (DTS) is the most mature technology, followed by distributed strain sensing (DSS). The latter technology, developed by Shell and Baker Hughes under the product name RTCM (Real Time Compaction Monitoring), allows operators to monitor tiny well deformations during the lifetime of a well (Earles et al. 2010). Both technologies can be combined, and fiber-optic pressure sensing capabilities (often labeled DPS) provide complementary data to this mix of sensing technologies (Available DPS systems tend to provide single- or multipoint pressure readings as opposed to true distributed pressure measurements, it should be noted.) Other fiber-optic sensing technologies, such as distributed acoustic sensing (DAS) and distributed chemical sensing (DCS), are less mature but are expected to hit the market in the next few years. DAS turns a standard telecom fiber deployed over an entire well path into a permanent array of microphones. DCS, the latest addition to the growing toolbox of fiber-optic techniques, will allow the detection of specific molecules along the full inflow area of producing wells. Last year, Shell embarked on a collaboration with QinetiQ, based in the UK, to evaluate the potential of DAS for oil and gas applications, and this year Shell entered into a similar arrangement with TNO, based in the Netherlands, with the aim of derisking DCS technology. Currently, the DAS technology is undergoing field trials, while DCS is in an early derisking phase.

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“…Since the mid-1990s, Distributed Temperature Sensing (DTS) has been used downhole to monitor the temperature along the wellbore (Williams, 2000). More recently, in 2009 the first downhole Distributed Acoustic Sensing (DAS) measurement was made (Molenaar, 2011), which has provided a rich new set of capabilities applicable in a wide range of downhole monitoring applications.…”

Section: Introductionmentioning

confidence: 99%

Cloud-Based Solution for Permanent Fiber-Optic DAS Flow Monitoring

Richards¹,

Bartlett²,

Onen³

et al. 2015

SPE Digital Energy Conference and Exhibition

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In 2014, a first permanent installation of a fibre-optic (FO) distributed acoustic sensing (DAS) system was piloted in a tight gas well in Northern British Columbia. The project had three goals; to permanently monitor flow rates along the entire well bore, to make that information available to collaborative teams worldwide in real-time and to advance the system for future installations.In oil and gas field development there is often a lack of frequent quality well and reservoir surveillance (WRS) data for quality decision making; leaving significant reservoir or well performance uncertainties potentially leading to suboptimal reservoir development. The need for frequent and good quality surveillance data is highest in complex reservoir developments such as unconventional plays, waterflooded reservoirs, thermal and chemical Enhanced Oil Recovery projects.Often, well surveillance data is not acquired in practice because of concerns associated with production deferment, costs & logistics, HSE exposure or because it creates operational risks associated with well interventions when using conventional logging methods.The attractiveness of FO-based surveillance lies with the fact that once the passive FO cable has been installed, no subsequent well interventions are required to collect downhole data; allowing for continuous (long-term) measurements or repeated measurements as and when required while eliminating the concerns associated with conventional logging methods.The pilot system deployed at the well site is continuously measuring and recording qualitative and quantitative flow information. Using a secure web browser, the asset team can access the real-time and historical data when required or share with collaborative teams worldwide. The pilot has helped identify where improvements can be made in the enabling Distributed Sensing infrastructure such as handling and evaluation of the large data volumes, seamless data transfer, the robustness of the system installation and the overall integration of data into the full workflows. It will take further development of the system to implement all these improvements, but it is clear that FO based applications will play a key role in future well and reservoir surveillance.This paper presents the system architecture and details the lessons learnt in designing, commissioning and running this system including the extraction of low data rate, actionable, qualitative data from distributed fibre-optic sensors and the IT challenges of creating a reliable, permanently installed system.

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First Downhole Application of Distributed Acoustic Sensing (DAS) for Hydraulic Fracturing Monitoring and Diagnostics

Cited by 56 publications

References 4 publications

Using Distributed Optical Sensing to Constrain Fracture Models and Confirm Reservoir Coverage in the Permian Basin

Using Distributed Optical Sensing to Constrain Fracture Models and Confirm Reservoir Coverage in the Permian Basin

Fiber-Optic Sensing Technology Providing Well, Reservoir Information - Anyplace, Anytime

Cloud-Based Solution for Permanent Fiber-Optic DAS Flow Monitoring

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